Notice of Proposed Rule Making

Transcription

1 Notice of Proposed Rule Making Oregon, Washington and Idaho Natural Gas Pipeline Safety Seminar June 17 18, 2009 Bruce L. Paskett, P.E.

2 Pipeline Safety Improvement Act of 2002 D.O.T. Inspector General Testimony July 2004 AGF Study January 2005 PHMSA Phase I Investigations December 2005 GPTC DIMP Guidance December 2006 PIPES Act December 2006 Distribution Integrity Management Rule NOPR

3 Mandated OPS to develop a regulation for TIMP Required natural gas transmission pipeline operators to identify lines in high consequence areas (HCAs) Perform risk analysis of transmission lines in HCAs Conduct baseline integrity assessments of top 50% riskiest pipelines using ILI, hydro testing, ECDA or equivalent technology by December 17, 2007 Conduct baseline integrity assessments of remaining pipelines in HCAs by December 17, year reassessment intervals

4 Accident trends for gas distribution exceed hazardous liquid and gas transmission combined No requirement for integrity management had been imposed on distribution pipeline operators Proposed distribution integrity management with elements and risk management principals similar to TIMP

5 Three element strategy proposed by I.G. Understand the infrastructure Identify and characterize threats Determine how to manage risks (prevention, detection and mitigation)

6 Safety Performance and Integrity of the Natural Gas Distribution Infrastructure Scope of work Detailed analysis of industry s safety performance Overview of current regulations and industry practices to address threats to distribution infrastructure Differentiate natural gas transmission pipelines from distribution pipelines

7 Stakeholders: AGA Industry APGA NAPSR NARUC DOT / PHMSA

8 Major findings (Serious incidents from ) Natural gas distribution pipelines are very safe 40% decrease in serious incidents Outside force was the major cause of serious incidents (47%) Predominate component of outside force incidents was third party damage (35% of incidents) Other threats accounted for less than 10% each When normalized per 100,000 miles, serious incidents for gas distribution are similar to gas transmission

9 Allegro Energy Consulting And Now, the New Small Buckets (i.e., 2 nd -Level Causes): Hazards, Actors Number of Incidents, % Third Party 29% Vehicle % Corrosion 7% Nat'l Forces Oper Excav/ Mech Dam'g Fire First Other Outside 5% Mat'l/ Weld 7% Oper Equip/ Oper Error 12% Unk. Misc. Other Cheryl J. Trench, 2004

10 Phase 1 investigations formed the foundation for the Distribution Integrity Management Program (DIMP) Rule NOPR

11 Scope: Collect and analyze available information and reach conclusions relative to integrity management principles for gas distribution pipelines Provide recommendations to PHMSA for DIMP Rule

12 Stakeholders: AGA Industry APGA NAPSR NARUC PHMSA IAFC (International Association of Fire Chiefs) Public

13 Four Multi Stakeholder Work / Study Groups: Strategic Options Group Risk Control Practices Group Excavation Damage Prevention Group Data Group

14 Key Findings: Distribution pipelines are safe, but there is room to improve Current regulations do not include the concept of risk based integrity management

15 Key Findings (cont d): Impractical to apply transmission IMP requirements to distribution infrastructure Entire distribution system covered by DIMP Plan, so there is no need to identify HCAs or sites Diversity between gas distribution operators makes it impractical to impose prescriptive requirements to all operators

16 Key Findings (cont d): Excavation damage presents the greatest threat to distribution safety so damage prevention provides the greatest opportunity for improvement States with comprehensive damage prevention programs including effective enforcement have a lower rate of damages

17 Enhanced communications operators and excavators Support and partnership of all stakeholders Performance measures for locating Partnership in employee training Partnership in public education

18 Enforcement agencies as partner to resolve disputes Fair / consistent enforcement of the One Call Law Use of technology to improve process Analysis of data to improve program effectiveness

19 Key Findings (cont d): EFVs should be considered as a risk management alternative and not mandated

20 Key Recommendations to PHMSA for DIMP: High level flexible regulation Need for implementation guidance Nationwide education program (811 One Call) Continued research and development

21 Develop and implement a written IM plan Know your infrastructure Identify threats, existing and potential Assess and prioritize risks Implement appropriate measures to mitigate risks Measure performance, monitor results, and evaluate program Report performance measures

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23 Excavation damage prevention / response DOT grants to states w/ effective damage prevention programs (9 Elements) Enforcement transparency DIMP Rule by December 31, 2007 EFVs for single family residential services installed after June 1, 2009

24 Prescribes the proposed minimum requirements for Distribution Integrity Management Programs (DIMPs) for gas distribution pipelines

25 What Must An Operator Do? a) No later than 18 months after the final rule, operators must implement a written program b) Written procedures for developing, implementing and improving elements

26 Required DIMP Elements a) Knowledge demonstrate understanding of distribution system 1) Characteristics of system to address threats and risk 2) Information from past design and operations

27 Required DIMP Elements 3) Identify additional information to be gathered over time 4) Develop process for continuous improvement of program 5) Retention of data for future installations, including location and material

28 Required DIMP Elements b)identify threats corrosion, natural forces, excavation damage, other outside forces, material / weld failure, equipment malfunction, inappropriate operation, other

29 Required DIMP Elements b)threats must gather data from: Incident and leak history Corrosion control records Continuing surveillance records

30 Required DIMP Elements b)threats must gather data from: Patrolling records Maintenance history One Call and excavation damage data Human error / PTP

31 Required DIMP Elements c) Evaluate and Prioritize Risk Evaluate the relative risk of each threat Consider each (current and potential) threat, likelihood and consequences May subdivide into regions with similar factors

32 Required DIMP Elements d)implement measures to address risk Effective leak management program Enhanced [Effective] excavation damage prevention program Separate Assuring Individual Performance section for human error

33 Required DIMP Elements e)measure performance, monitor results Hazardous leaks eliminated by cause Number of excavation damages Number of excavation tickets

34 Required DIMP Elements e) Measure performance, monitor results Number of EFVs installed Number of leaks eliminated by cause Hazardous leaks eliminated by material

35 Required DIMP Elements f) Periodic evaluation and improvement Continually evaluate threats and risks Extrapolate threats to other locations Periodically evaluate effectiveness of PTP Program evaluation at least every 5 years

36 Required DIMP Elements g) Report Results Hazardous leaks eliminated by cause Number of excavation damages Number of excavation tickets Number of EFVs installed

37 Plastic Pipe Failure Reporting Operators must report material failures of plastic pipe (fittings, couplings, joints) no later than 90 days after failure. Include location, size, material type, nature of failure, manufacturer, lot number, other marking data

38 Excess Flow Valve Requirements a) Applies to new or replaced services to single family residences b) Must install EFV on service line 90 days after final rule unless impractical. Conflicts with congressional mandate

39 Records Requirements Except for , must keep records demonstrating compliance for the useful life of the pipeline

40 Minimum Record Requirementsa) Written DIMP Program per b) Documents supporting threat identification c) Written procedure for ranking threats

41 Minimum Record Requirements (d) Documents to support any decision (e) Records for any changes to the program and the reason it was made (f) Records for performance measures (10 years)

42 Deviation From Periodic Inspection a) Operators may propose to reduce the frequency of periodic inspections required by 192 if they can show that there is not a significant increase in risk b) Submit proposal to PHMSA or state agency

43 Simpler DIMP Elements for Master Meter and LPG Operators

44 Major Issues With Proposed Rule 1) Short time to implement 18 months 2) Excessive documentation requirements for decisions and changes 3) Assuring individual performance / PTP 4) Plastic pipe failure reporting (PPDC)

45 Expected Resolution of Issues 1) Short time to implement 18 months (no change) 2) Excessive documentation requirements for decisions and changes reduced

46 Expected Resolution of Issues 3) Assuring individual performance / PTP / Human Error delete from final rule 4) Plastic pipe failure reporting (PPDC) delete from final rule. Report mechanical coupling failures w/ Annual Report

47 Expected Resolution of Issues 5) Definition of hazardous leak and damage included in final rule 6) Alternative inspection intervals clarify decision process, no net increased risk 7) Low stress transmission lines separate rule making

48 DI guidance TG developed the DIMP guidance in parallel with the rule to provide natural gas operators with recommendations to comply with the DIMP Rule

49 Know the distribution system and how it is operated and maintained Data Mining and Integration Identify threats to address associated risks Evaluate and rank groups based on associated risks Identify and implement appropriate measures to manage risk Measure performance and monitor results Periodically evaluate and improve the program Make periodic reports to government agencies

50 Data Mining and Integration Know the materials, type of construction and O&M of the system Records and data may exist in many forms, including SMEs Use the best information available and update when better information becomes available An operator would not have to dig up it s system just to collect information Must record the location and materials of new pipe

51 System information should be gathered during construction activities on existing facilities and during O&M activities To the extent possible, the operator should use information collection procedures that are already in place New collection activities should be developed only if the existing procedures are not adequate

52 Basic Information D.O.T. Annual Report Information - B.1

53 D.O.T. Annual Report Information - B.2

54 D.O.T. Annual Report Information - B.3

55 D.O.T. Annual Report Information - C

56 Pipe specs, diameter, grade, w.t., yield S (steel) Manufacturer, SDR / w.t., spec (plastic) Construction data year installed, method Installation method open trench, HDD, casings Corrosion control Coatings (coal tar, FB epoxy) Galvanic or impressed current Electrical isolation

57 Inspection and survey data Leakage repair records Corrosion inspection records Material failures Excavation activity third party damages Pipe inspection reports Geologic conditions

58 Corrosion Natural forces Excavation Other outside forces Material or welds Equipment Operations Other

59 Group facilities into categories (buckets) based on common traits and problems Examples: Cast Bare Bare Coated Good Problem Iron Steel Steel Steel PE Plastic (w/o CP) (w/cp) (w/cp)

60 Pipe material Pipe specifications Pipe type (main / service) CP history Specific brand / model of fitting or equipment Age / vintage Geographic or geologic area

61 O & M history Installation practices One Call system (mandatory or voluntary) Level of construction activity Pipe excavation methodology (open trench, etc.) Soil type Soil temperature

62 Evaluate and rank groups based on associated risks

63 Risk is the product of the likelihood of a problem occurring and the consequences that could be caused by the problem if it occurs Risk = Likelihood x Consequences

64 Based on identified threats, can help determine if additional risk management practices are needed Should result in a relative risk ranking of facilities or groups of facilities (pipe or components) relative to other facilities or groups of facilities

65 Many methods can be used, but must result in a relative risk ranking Two general approaches: Use of subject matter experts (SMEs) Use of mathematical (algorithm) methods

66 Have an SME review available data Conduct periodic inter departmental meetings Conduct periodic SME meetings Centralized department to review data Electronic database or work management system Commercial risk evaluation software

67 Review data from O&M activities, special field surveys, etc., to determine where problems have occurred and if problems will likely occur in the future Assign a relative risk ranking to each facility or group of facilities

68 Can use existing off the shelf or internally developed software that performs risk evaluation Commercial DIMP risk management software programs are under development

69 Step 1: Group facilities with common traits that experience problems Common traits may include pipe material, CP history, vintage, O&M history, geographical area, amount of construction activity, etc. Evaluate problem trends; stable or improving trends may require no further action

70 Facilities or groups of facilities that do not experience problems may be removed from the risk evaluation and require no further action (except excavation threats)!

71 Step 2: Risk Ranking One approach create a risk matrix (frequency and consequence) and assign values to each facility or group based on the known O&M history and input from SMEs Assign a value to each factor

72 Low Medium High Few problems, excavators generally responsive, good map and locating records Moderate number of problems, excavators not very responsive, moderate map and locating records High number of problems, excavators nonresponsive, poor or no map and locating records

73 Low Medium High Rural location, small diameter pipe, low operating pressure Residential location, medium diameter pipe, medium operating pressure Predominantly multi-story buildings, large diameter pipe, high operating pressure

74 Consequence Factor (Multiplier*) Frequency Factor (Multiplier*) Low (1) Medium (2) High (3) Low (1) 1 x 1 1 x 2 1 x 3 Medium (2) 2 x 1 2 x 2 2 x 3 High (3) 3 x 1 3 x2 3 x 3 *Determined by Operator

75 Validate the risk ranking results by asking: Do the results and O&M records focus on the same facilities or groups of facilities? Do the results agree with the SME experiences? If the answers are no, may want to iterate the risk evaluation process, gather more data or reevaluate the SME perspective The differences need to be understood and resolved

76 Based on the results of the relative risk ranking, implement appropriate techniques to manage risk Facilities or groups of facilities with low relative risk may require little or no risk management techniques Facilities or groups of facilities with high relative risk will require additional risk management techniques (A/A Actions)

77 Risk management techniques may address the probability or consequences of problem DIMP NOPR requires implementation of an effective leak management program DIMP NOPR also requires enhancement of an operator s excavation damage prevention program

78 Measure performance and monitor results Determine if additional or accelerated actions are effective Choose metrics that can be counted, tracked and monitored Select a critical few measures

79 Periodically review the written program for appropriateness (minimum 5 years) Review success and effectiveness of risk management practices

80 Report results to regulatory authorities DIMP Rule will require periodic reporting of key performance metrics Operators will need processes to gather and report data per regulatory deadlines

81 DIMP Rule Requirements: Will require a pipeline facility management program, not a replacement program Will not require integrity assessments Will require data mining, integration, and analysis to know your system and complete relative risk ranking of facilities

82 DIMP Rule Requirements: Some groups of facilities will require implementation of A/A actions Groups of facilities that do not experience problems will not require additional / accelerated (A/A) actions An effective leak management program and enhanced excavation damage prevention program are critical

83 DIMP Rule Requirements: EFVs required on new / replaced single family residential services (June 1, 2008) Operators must report performance measures to regulators hazardous leaks by cause, excavation damages, One Call tickets, number of EFVs installed Operators must report plastic pipe material failures (pipe, fittings, joints) within 90 days

84 DIMP Rule Requirements: Plan must address assuring individual performance / PTP to address human error May allow operators to reduce the frequency of current 192 inspections / tests based on the results of risk analysis GPTC guidance is recommendations

85 DIMP Rule Requirements: Operators need to work closely with state (NAPSR) regulators A flexible rule equals flexible regulation

86 June 2008 DIMP NOPR 4Q 2009 Final DIMP rule Mid 2011 Begin implementation of DIMP program (18 months after final rule)

87 Questions? Thank you